Multi-phase composition and method for mitigating fracturing hits of underground wells

ABSTRACT

There is provided a method for mitigating fracturing hits on an underground well consisting of inserting a multi-phase composition comprising gas and a nanoparticle fluid into a pre-existing well for reducing of not eliminating any fracture driven interference at the pre-existing well; and a multi-phase composition for mitigating fracturing hits on an underground well, which consists of a gas and nanoparticle fluid combined to form a well treatment fluid adapted to be injectable into the underground well for resisting fracturing hits on the underground well.

BACKGROUND

The present invention relates to compositions and methods that use gascompositions to facilitate the recovery of hydrocarbons from undergroundwells, and to stabilize interactions between a plurality of adjacentwells.

Detrimental interaction or interference among underground wells, orwell-to-well interference/interaction, can occur where there is anundesired intersection, pressure or communication between and amongseparate adjacent wells. Such interactions result from and areassociated with fracture driven interactions among the earth and rockwhich surrounds the wells. These interactions, or so called “Frac Hits”,describe a phenomenon, wherein an existing “Initial” or “Parent” well ina well field is structurally and/or functionally compromised by a newlyadjacent “Infill” or “Child” well in the same field and offset from theParent, whereby a fractured region or zone of the Child well intersectsor communicates with a fractured region or zone of the Parent well suchthat production of one or both of the Parent and Child wells isadversely impacted. In other words, the Frac Hits are fracture driveninterference or interactions (FDIs) which result from a new Child wellbeing drilled such that the (FDIs) communicate with a Parent or otherexisting well to adversely affect production of the Parent or otherexisting well(s). The distance between a Parent and a Child well, andthe distance between adjacent Child wells, may be hundreds of feet tothousands of feet at the closest point. The Frac Hit may include, amongother things, an invasion of a fracturing fluid, a stress shadowingeffect or formation damage to an existing Parent well from a neighboringChild well which is being fractured. This invasion can negatively impactboth the Parent and Child wells. And, it is possible that a Child wellmay adversely impact other neighboring Child wells with such Frac Hits.The significance of this detrimental impact varies, but is known tocause a reduction in a range of from 60%-100% of the production capacityof the Parent and/or Child wells. The Parent well production isadversely impacted by water from the fractured Child well seeping intoor invading the Parent well or damage to the fracturing network of theParent well. This invasion results in an increase in unwanted waterproduction from the Parent well, and a decrease in hydrocarbonproduction from the Parent well with little chance of hydrocarbonrecovery, all of which is undesirable to oil and gas operators. TheParent and Child wells each may run substantially horizontallyunderground and may or may not be parallel with each other.

The undesired interference, intersection, communication or invasion(individually and collectively the “Frac Hits”) between the Parent andChild wells can damage each one or both of the wells in one or moreways, and destroy productivity of each. For example, invasion offracturing fluids from one well into another well; or the phenomenon of“stress shadowing”, wherein stress in the ground or surrounding veins orformations of rock is transmitted to one of more adjacent wells toadversely impact same, will each thereby result in the reduction of bothwell productivity and the mechanical integrity of the well. Thesedetrimental events can be exacerbated during unconventional drillingoperations to maximize hydrocarbon reservoir recovery during, forexample, Child well drilling in more densely packed underground shalereservoirs or formations which extend among the Parent and Child wells.This undesirable event is further exacerbated in conditions where thearea is reduced between each of the Child and corresponding Parentwells.

The horizontal drilling of a Child well along a shale formation in aregion of the Parent well, and the plurality of Child wells to collectthe gas and hydrocarbons from the shale layer, increases the structuralstress upon the wells. Such stress can further compromise and perhapscollapse the Parent and/or Child wells.

There is accordingly needed cost-effective compositions and relatedmethods to enhance hydrocarbon recovery in existing Parent wells whilemitigating Frac Hits upon the Parent wells from the fracturing of theneighboring or related Child wells.

SUMMARY

There is therefore provided herein a multi-phase composition embodimentof a foam, energized solution or optionally an emulsion embodiment forenhancing hydrocarbon recovery and minimizing Frac Hits in a Parent orother type well, wherein a mixture comprised of a gas selected from thegroup consisting of carbon dioxide (CO₂) and nitrogen (N₂); andnanoparticles form a foam, an emulsion, or an energized solution forloading into the well to be protected from Frac Hits.

There is also provided herein a method embodiment for enhancinghydrocarbon recovery and minimizing Frac Hits in Parent or other typewell, consisting of injecting the components for a multi-phasecomposition, foam, energized solution or an emulsion comprising the gasand nanoparticles into a Parent well at least before and optionallyduring a fracturing of a Child well for stabilizing the Parent well.

Other embodiments call for the foam, energized solution or the emulsionto include a gas selected from the group consisting of natural gas,natural gas liquids, liquefied carbon dioxide, and mixtures thereof.

Another embodiment calls for or includes the gas injected before thenanoparticles are injected into the Parent well, after the nanoparticlesare injected into the Parent well or concurrent with injection of thenanoparticles into the Parent well at a select location, wherein a totaltreatment of the foam, energized solution, or emulsion used is held inthe well as appropriate until such time as the well can re-opened forproduction.

Another embodiment calls for the method wherein a treatment fluid mayalso include one or more injectants selected from the group consistingof surfactants, fresh water, potassium chloride (KCl) water,well-produced water, diverters, and any other injectant used in oilfield remediation.

Another embodiment includes a method wherein the treatment fluidcomprises gas and colloidal silica nanoparticles.

Another embodiment includes a method wherein the colloidal silicananoparticles are brine resistant colloidal silica nanoparticles.

Another embodiment includes a method wherein the treatment fluidconsists of gas, brine resistant colloidal silica nanoparticles andsurfactants; and optionally at least one terpenes.

Another embodiment includes a method wherein the treatment fluidconsists of gas and less than 0.1 wt, % nanoparticles.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present embodiments, referencemay be had to the following detailed description taken in conjunctionwith the attached drawing(s), of which:

FIG. 1 shows a plan schematic view of an example of the relationshipbetween a Parent well and a Child well. The solid black line representsa Parent or an existing well, and the black dashed line represents aChild or new well drilled and being prepared for initial fracturestimulation. The smaller hatched lines represent natural fractures inthe reservoir rock.

DETAILED DESCRIPTION

Before explaining the inventive embodiments in detail, it is to beunderstood that the invention is not limited in its application to thedetails of construction and arrangement of steps or parts illustrated inthe accompanying drawings, if any, since the invention is capable ofother embodiments and being practiced or carried out in various ways.Also, it is to be understood that the phraseology or terminologyemployed herein is for the purpose of description and not of limitation.

In the following description, terms such as a horizontal, upright,vertical, above, below, beneath and the like, are to be used solely forthe purpose of clarity illustrating the invention and should not betaken as words of limitation. The drawings, if any, are for the purposeof illustrating the invention and are not intended to be to scale.

The term “associate with” or “associating with” as used herein includes,for example, covalent bonding, hydrogen bonding, electrostaticattraction, London forces and Hydrophobic interactions.

The term “foam” as used herein refers to foam quality, such as forexample a “95 quality foam” is a foam that is 95% gas and 5% liquid. Ina foam, at least 52% of the composition is in the gas phase. That is,foam consists of discontinuous gas bubbles suspended in a liquid.

The term “emulsion” as used herein refers to at least two (2) liquidsthat are immiscible.

An emulsion is composed of discontinuous droplets of liquid suspended ina second immiscible liquid.

The term “energized solution” as used herein refers to a solution whereless than 52% of the solution is in the gas phase.

The term “saturate” or its inflected forms and tenses as used hereinrefers to filling completely with something that permeates or pervades,or to load to capacity.

Generally, and with respect to the present embodiments, pre-loading of aParent well with the treatment embodiment of the present inventionrequires the placement of fluids within the well to some specifiedvolume or pressure. A foam or an emulsion, with foam qualities as muchas 98 percent (%), of gases and nanoparticles of the present embodimentsare used to minimize the amount of fluids required to be inserted intothe well, while also mitigating Frac Hit to a maximum extent possible,all the while enhancing hydrocarbon recovery (oil and natural gas) fromthe well.

The present embodiments provide an effective mechanism for building adesired pressure barrier or deterrent in the Parent well to minimize oreliminate any fracture driven interaction or FDIs created during thefracturing of the Child or Infill well or wells, and enhancing recoveryfrom the treated Parent well, including recovery from other wells influid communication with the treated well.

For hydraulic fracturing to recover hydrocarbons, such as for exampleoil and natural gas, a well may be drilled from a surface pad verticallydownward in a well field for many thousands of feet into the earth to asub-surface “kick-off” point, wherein the well bore is turned to extendhorizontally from the vertical well bore. This kick off point will bethe beginning of the Parent well (extending horizontally) in the field.Accordingly, a single field may have a plurality of vertical well bores,the first one of which is the initial vertical bore and from which aParent well extends horizontally from the kick-off point. Eachsuccessive vertical well bore also has a kick-off point, and from eachthere extends horizontally a Child well in the same field and at adistance of from hundreds of feet to thousands of feet adjacent one or aplurality of adjacent Child wells in the same field. Vertical portionsof the Parent and Child wells could be from tens to thousands of feetdistant from each other, depending upon the surface pad structureemployed and the sub-surface rock structure bored through.

Referring to a single Parent (or “parent”) well and a single Child (or“child”) well as shown in FIG. 1 for the sake of brevity, the child mayextend for miles and is usually through the shale reservoir or targetedhydrocarbon formation in the earth, much below the water table.

The child well is lined with a steel pipe, similar to surface casingused in the parent well, and a cement exterior sleeve disposed in thespace between an exterior of the steel pipe and the child bore hole.

For parent and child well completion, there are two fracturingtechniques. First, a plug and perf is a cased hole completion approach,wherein a bridge plug and perforation (perf) gun are placed in a desiredstage within a well bore. With the plug set, the perf gun fires chargesto make holes in the casing, thereby penetrating into the rock formation(the “reservoir section”) containing the hydrocarbon between the setplugs. Hydraulic fracturing of the well then takes place, and “frac”fluid is pumped into the section. This process is repeated for eachstage of the casing, with the downhole tools moving from a furthest ordistal end of the wellbore back toward the beginning or proximate end ofthe wellbore until all the stages have been fractured. Afterward, theplugs are drilled or milled out for the hydrocarbons to escape backthrough and out of the well bore for collection at the surface pad.Second, and as an alternative to plug and perf, sliding sleeves may beused to shut off flow from one or more reservoir sections or to regulatepressure between sections during multi-stage frac jobs.

The fractures created from the perforations or “perfs” during thefracturing process provide fluid communication between the shalereservoir containing the hydrocarbons and the child well bore whichallows the hydrocarbons to flow from the shale into the child well boreand through same to the vertical portion of the well and out of the wellhead at the surface for collection and use.

The present method embodiments, and the present foam, energized solutionor emulsion embodiments, call for a foam, energized solution or anemulsion to be inserted (via for example injection or other manner ofdelivery) into the parent well to shore-up same, thereby effectivelypressurizing the parent so that same is less likely to be structurallycompromised during the Frac Hits from the fracturing of the childwell(s). The foam, energized solution or the emulsion is more stablethan other known fluids for this type of application and therefore,provides a more uniform and reliable pressure hold in the parent due tothe leak-off from the foam, energized solution or the emulsion beingslower than would otherwise occur with other known, less viscousliquids, foam, energized solution or an emulsion.

Additionally, the pressure hold may be required in the parent well foras much as two (2) weeks to accommodate the time necessary for thefracturing of a plurality of neighboring child wells emanating fromtheir respective vertical bores and therefore, the foam, energizedsolution or emulsion is physically better suited for increased residencetimes than other less viscous liquids for such an extended period oftime. The multi-phase composition also minimizes (i) the use of water orother fluids that require a more extensive off-loading of the parentwell to get it producing again after the fracturing of the child well oroffset wells is completed, ii) any well clean-up process because lessfluids require off-loading and the gas phase can energize the removal ofexcess fluids, and (iii) the possibility of damage from excessive fluidresidence time and fluid loading in the parent well.

The following method embodiment can be used to meet the necessaryrequirement of pressuring-up the parent well, sustaining or maximizingthe maintaining of pressure in the parent, optimizing recovery ofhydrocarbons out of the parent well, and providing a practical manner bywhich to execute the present composition and method on a plurality ofwells for completion of an infill well drilling program.

The foam, energized solution or the emulsion used in the presentembodiments can also include surfactants alone or in combination withthe nanoparticles such as colloidal silica nanoparticles, brineresistant colloidal silica nanoparticles, and brine resistant colloidalsilica nanoparticles in combination with surfactants and optionally withterpene.

The nanoparticles used in the present embodiments can include inorganicnanoparticles, surface-modified inorganic nanoparticles, organic acidand base surface modification agents for non-silica inorganicnanoparticles, micro emulsions, and micro emulsions comprisingnanoparticles/surface-modified nanoparticles.

The present embodiments provide a foam, energized solution or anemulsion of nanoparticles with gas or surface-modified nanoparticleswith gas to reduce Frac Hit production interference during oil orhydrocarbon recovery. In certain oil or hydrocarbon recovery methodsnanoparticles or surface-modified nanoparticles can act synergisticallywith surfactant or replace surfactant in reducing interfacial tensionbetween oil or hydrocarbons and aqueous systems. Nanoparticles orsurface-modified nanoparticles can also act to remove oil andhydrocarbons from rock surfaces via increased disjoining pressure at the3-phase contact angle between oil/hydrocarbon—water/brine—rock (forexample shale). An appropriate nanoparticle composition and method or asurface-modified nanoparticle composition and method can be used toreduce surface tension of a desired fluid.

In methods where Frac-Hit mitigation strategies are employed it isadvantageous to preload a parent well with fluids comprisingnanoparticles or surface-modified nanoparticles to take advantage oftheir tendency to improve oil and hydrocarbon removal for theaforementioned reasons.

The nanoparticle or surface-modified nanoparticle fluids are preferablyindividual, unassociated (i.e., non-agglomerated) nanoparticlesdispersed throughout the dispersing liquid and preferably do notirreversibly associate with each other.

Nanoparticles of interest can be chosen from the following groups:polymers, micro emulsions of dispersed liquids, or inorganic particles.Preferably the nanoparticles are inorganic or micro emulsions ofdispersed liquids. Examples of suitable inorganic nanoparticles includecolloidal Silica and metal oxide nanoparticles including Zirconia,Titania, Ceria, Alumina or oxides of Aluminum, Iron oxide, Vanadia,oxides of Antimony, oxides of Tin, oxides of Zinc.

In a further embodiment, combinations of inorganic oxides can also beused to make combination nanoparticles such as Alumina modifiedcolloidal Silica, Calcium oxide modified colloidal Silica, Magnesiumoxide modified colloidal Silica, and similar colloidal Silica systemsmodified with oxides of non-silica inorganic oxides.

The nanoparticles used in the present composition and method embodimentsmay have an average particle diameter of (i) less than 100 nm, (ii) notgreater than 50 nm for some applications, and (iii) or from about 3 nmto about 30 nm. If the nanoparticles are aggregated, the maximumcross-sectional dimension of the aggregated particle is within any ofthe foregoing ranges. Useful surface-modified zirconia nanoparticlesinclude a combination of oleic acid and acrylic acid adsorbed onto thesurface of the nanoparticle.

Inorganic nanoparticle fluids can, in a further embodiment, comprisesurface-treated nanoparticles. Suitable classes of surface modifyingagents include for example organosilanes, organic acids, organic bases,and alcohols. Particularly useful surface modifying agents includeorganosilanes. Organosilanes, include, but are not limited to,alkylchlorosilanes, alkoxysilanes (e.g. methyltrimethoxysilane,methyltriethoxysilane, ethyltrimethoxysilane, methyltriethoxysilane,n-propyltrimethoxysilane, n-propyltriethoxysilane,isopropyltrimethoxysilane, isopropyltriethoxysilane,butyltrimethoxysilane, butyltriethoxysilane, hexyltrimethoxysilane,octyltrimethoxysilane, 3-mercaptopropyltrimethoxysilane,phenyltrimethoxysilane, glycidoxypropyltrimethoxysilane,methacryloxypropyltrimethoxysilane, methacryloxypropyltriethoxysilane,3-ethyl-3-oxetanyloxymethylpropyltrimethoxysilane,vinyltrimethoxysilane, vinyldimethylethoxysilane,vinylmethyldiacetoxysilane, vinylmethyldiethoxysilane,vinyltriacetoxysilane, vinyltriethoxysilane, vinyltriisopropoxysilane,vinyltriphenoxysilane, vinyltri(t-butoxy)silane,vinyltris(isobutoxy)silane, vinyltris(isopropenoxy)silane,vinyltris(2-methoxyethoxy)silane, (3-triethoxysilyl)propylsuccinicanhydride, trialkoxyarylsilanes, isooctyltrimethoxysilane,N-(3-triethoxysilylpropyl)methoxyethoxy ethyl carbamate,N-(3triethoxysilylpropyl)methoxyethoxyethoxyethyl carbamate,ureidopropyltrimethoxysilane, 3-acryloyloxypropyltrimethoxysilane;polydialkylsilanes including polydimethylsiloxane; arylsilanes includingfor example substituted and unsusbstituted arylsilanes; alkylsilanesincluding for example substituted and unsubstituted alkylsilanesincluding for examples methoxy and hydroxyl substituted alkylsilanes,and combinations thereof.

Embodiments of nanoparticle fluids comprised of micro emulsions suitablefor use in the present embodiments include oil in water microemulsionscomprising oil phase, cosolvent phase, surfactant or combination ofsurfactants, and an aqueous continuous phase. In a further embodimentthe microemulsion fluid can itself comprise nanoparticles.

Brine resistant silica sol may be used with the present embodiments, assuch includes colloidal silica that has been surface treated in order toresist brine and thereby remain functional and not gelled, even in thepresence of significant amounts of salt/brine in the well formation.Brine resistant colloidal silicas may also be used with the presentembodiments.

Colloidal silica nanoparticles and brine resistant colloidal silicananoparticles are commercially available from Nissan Chemical AmericaCorporation.

Brine Resistant Colloidal Silica Nanoparticles in combination withsurfactants and optionally in combination with terpenes are commerciallyavailable from Nissan Chemical America Corporation under the tradename“nanoActiv® HRT and nanoActiv®EFT”.

Brine resistant colloidal silica is known to be electrostaticallystabilized by surface charge, where like charges at the silica particlesurface repel the like charges of other particles leading to a stabledispersion—this is part of the definition of a colloidal dispersion. Inbriny water, where the water/dispersant contains dissolved salt ions,colloidal particles experience a disruption or shielding of particlesurface charge leading to a reduction in particle-to-particle repulsionand reduced colloidal stability.

It is known to surface-treat colloidal silica to try to avoid the lossof stability caused when the colloid encounters disruptive conditions,such as brine. However, it is known that some surface treated silica ismore brine resistant than others.

With regards to brine resistance of colloidal silica, it is believedwithout being bound thereby, that the hydrophilicity/hydrophobicity ofthe surface treatment is important as well as the amount of surfacetreatment relative to the available silica surface area.

Organic surface treatment can improve colloidal silica stability inbrine/high salinity water by addition of steric repulsion properties tosupplement electrostatic repulsion between particles. Hydrophilicorganic surface treatment is somewhat effective at adding this stericrepulsion property for improved brine resistance. A combination ofHydrophilic and Hydrophobic surface treatment in the correct proportioncan also form highly brine resistant surface treatment systems forcolloidal silica.

Adding some Hydrophobic character to colloidal silica is known inOrganic solvent systems. However, it is difficult to achieve in Aqueoussystems. In short, Hydrophobic character by definition is water-hatingand not prone to solubility or stability in water. It is desirable inthis work to add organic surface treatment to colloidal silica having acombination of Hydrophilic and Hydrophobic character—where the silicahas both excellent brine stability and the ability to perform well inremoving oil from rock surfaces, Combining Hydrophilic and Hydrophobiccharacter is well known in surfactant science but is not well known inorganic surface treatment for colloidal silica.

Engineered nanoparticles are expected to reduce the tendency of highmolecular weight hydrocarbons such as paraffin and scale to nucleateonto available surfaces and cause a reduction in recovery of desirablehydrocarbons.

Example(s)

An example of a method embodiment of the present invention calls forinserting a multi-phase composition of a gas and a nanoparticle solutioninto a pre-existing well for maintaining at least the existing pressureof the pre-existing well and if necessary a pressure slightly higherthan the existing pressure; and fracturing at least one secondary wellproximate to the pre-existing well; wherein the composition in thepre-existing well substantially reduces if not eliminates fracturingdriven interference of the pre-existing well from the fracturing of theat least one secondary well.

Another example of a method embodiment of the present invention includespressuring a parent well up to 2000-3000 psi prior to fracturing of achild well, and such method includes the following. The parent well,prior to fracturing of a new child well, is initially injected with 3000gallons of water followed by 300 tons of CO₂. To further build andmaximize pressure in the parent, there is used the foaming properties ofgas and nanoparticles, i.e. 36,000 gallons of a nanoparticle solutionare co-injected with 900 tons of CO₂. This second step may begin eitherbefore or during the fracturing of the child well. Depending upon theamount of time necessary to maintain pressure in the parent well, theCO₂ may continue to be injected into the parent after the co-injectionstep. This pressure hold may be required while another infill (or child)well is fractured.

Other embodiments of the present invention include—

A method for mitigating fracturing hits on an underground well,comprising: inserting a multi-phase composition comprising gas and ananoparticle fluid into a pre-existing well for reducing if noteliminating any fracture driven interference at the pre-existing well.

A method further comprising: fracturing at least one secondary well inproximity to the pre-existing well; and maintaining structural integrityof the pre-existing well with the multi-phase composition.

The method, wherein the inserting the multi-phase composition is at atime selected from the group consisting of inserting before thefracturing, during the fracturing, and after the fracturing.

The method, wherein the inserting the multi-phase composition comprisesinjecting the multi-phase composition into the pre-existing well.

The method, wherein the fracturing of at least one secondary well iswith hydraulic fracturing.

The method further comprising arranging the at least one secondary welltransverse to a longitudinal axis of the pre-existing well.

The method, wherein the gas of the multi-phase composition is insertedinto the pre-existing well at a time selected from the group consistingof before the nanoparticle fluid is inserted into the multi-phasecomposition, after the nanoparticle fluid is inserted into themulti-phase composition, and concurrent with the nanoparticle fluidbeing inserted into the multi-phase composition.

The method further comprising maintaining the multiphase composition inthe pre-existing well for reducing stress fracturing of the pre-existingwell; and removing the multi-phase composition from the pre-existingwell at a time for resuming recovery of hydrocarbons from thepre-existing well.

The method, wherein the gas is selected from the group consisting ofliquefied gas, vaporized gas and nanoparticles, carbon dioxide,nitrogen, natural gas, natural gas liquids, liquefied carbon dioxide,and mixtures thereof.

The method, wherein the multi-phase composition further comprises atleast one injectant selected from the group consisting of surfactants,fresh water, potassium chloride (KCl) water, diverters, and anyinjectant compatible for use in oil field remediation.

The method, wherein the nanoparticle fluid comprises colloidal silicananoparticles.

The method, wherein the colloidal silica nanoparticles comprise brineresistant colloidal silica nanoparticles.

The method, wherein the nanoparticle fluid comprises brine resistantcolloidal silica nanoparticles, and the multi-phase composition furthercomprises surfactants.

The method, wherein the multi-phase composition further comprises atleast one terpene.

The method, wherein the nanoparticle fluid comprises less than 0.1 wt. %of nanoparticles or optionally comprises a range of from 0.05 wt. % to16 wt. % of nanoparticles.

The method, wherein the pre-existing well comprises an underground borehole selected from the group consisting of a bore hole positioned belowa surface of the earth, and a bore hole positioned beneath a bottom of abody of water.

The method, wherein the body of water is selected from the groupconsisting of a lake, a sea, an ocean, and a littoral region.

The method further comprising saturating the pre-existing well with themulti-phase composition.

A multi-phase composition for mitigating fracturing hits on anunderground well, comprising: a gas and a nanoparticle fluid combined toform a well treatment fluid adapted to be injectable into theunderground well for resisting fracturing hits on the underground well.

The multi-phase composition, wherein the gas comprises from 95% to 98%of the well treatment fluid.

The multi-phase composition, wherein the gas is selected from the groupconsisting of liquefied gas, vaporized gas and nanoparticles, carbondioxide, nitrogen, natural gas, natural gas liquids, liquefied carbondioxide, and mixtures thereof.

The multi-phase composition further comprising at least one injectantselected from the group consisting of surfactants, fresh water,potassium chloride (KCl) water, diverters, and any injectant compatiblefor use in oil field remediation.

The multi-phase composition, wherein the nanoparticle fluid comprisescolloidal silica nanoparticles.

The multi-phase composition, wherein the colloidal silica nanoparticlescomprise brine resistant colloidal silica nanoparticles.

The multi-phase composition, wherein the nanoparticle fluid comprisesbrine resistant colloidal silica nanoparticles, and the multi-phasecomposition further comprises surfactants.

The multi-phase composition further comprising at least one terpene.

The multi-phase composition, wherein the nanoparticle fluid comprisesless than 0.1 wt. % of nanoparticles or optionally comprises a range offrom 0.05 wt. % to 16 wt. % of nanoparticles.

The multi-phase composition, wherein the well treatment fluid comprisesa fluid selected from the group consisting of a foam, an emulsion, andan energized solution.

The multi-phase composition, wherein the well treatment fluid saturatesthe underground well.

It will be understood that the embodiments described herein are merelyexemplary and that a person skilled in the art may make variations andmodifications without departing from the spirit and scope of theinvention. All such variations and modifications are intended to beincluded within the scope of the invention as defined herein and in theappended claims, if any. It should also be understood that theembodiments described above are not only in the alternative but can becombined.

What is claimed is:
 1. A method for mitigating fracturing hits on anunderground well, comprising: inserting a multi-phase compositioncomprising gas and a nanoparticle fluid into a pre-existing well forreducing if not eliminating any fracture driven interference at thepre-existing well.
 2. The method of claim 1, further comprising:fracturing at least one secondary well in proximity to the pre-existingwell; and maintaining structural integrity of the pre-existing well withthe multi-phase composition.
 3. The method of claim 1, wherein theinserting the multi-phase composition is at a time selected from thegroup consisting of inserting before the fracturing, during thefracturing, and after the fracturing.
 4. The method of claim 1, whereinthe inserting the multi-phase composition comprises injecting themulti-phase composition into the pre-existing well.
 5. The method ofclaim 2, wherein the fracturing of at least one secondary well is withhydraulic fracturing.
 6. The method of claim 2, further comprisingarranging the at least one secondary well transverse to a longitudinalaxis of the pre-existing well.
 7. The method of claim 1, wherein the gasof the multi-phase composition is inserted into the pre-existing well ata time selected from the group consisting of before the nanoparticlefluid is inserted into the multi-phase composition, after thenanoparticle fluid is inserted into the multi-phase composition, andconcurrent with the nanoparticle fluid being inserted into themulti-phase composition.
 8. The method of claim 1, further comprisingmaintaining the multiphase composition in the pre-existing well forreducing stress fracturing of the pre-existing well; and removing themulti-phase composition from the pre-existing well at a time forresuming recovery of hydrocarbons from the pre-existing well.
 9. Themethod of claim 1, wherein the gas is selected from the group consistingof liquefied gas, vaporized gas and nanoparticles, carbon dioxide,nitrogen, natural gas, natural gas liquids, liquefied carbon dioxide,and mixtures thereof.
 10. The method of claim 1, wherein the multi-phasecomposition further comprises at least one injectant selected from thegroup consisting of surfactants, fresh water, potassium chloride (KCl)water, diverters, and any injectant compatible for use in oil fieldremediation.
 11. The method of claim 1, wherein the nanoparticle fluidcomprises colloidal silica nanoparticles.
 12. The method of claim 11,wherein the colloidal silica nanoparticles comprise brine resistantcolloidal silica nanoparticles.
 13. The method of claim 1, wherein thenanoparticle fluid comprises brine resistant colloidal silicananoparticles, and the multi-phase composition further comprisessurfactants.
 14. The method of claim 13, wherein the multi-phasecomposition further comprises at least one terpene.
 15. The method ofclaim 1, wherein the nanoparticle fluid comprises less than 0.1 wt. % ofnanoparticles or optionally comprises a range of from 0.05 wt. % to 16wt. % of nanoparticles.
 16. The method of claim 1, wherein thepre-existing well comprises an underground bore hole selected from thegroup consisting of a bore hole positioned below a surface of the earth,and a bore hole positioned beneath a bottom of a body of water.
 17. Themethod of claim 16, wherein the body of water is selected from the groupconsisting of a lake, a sea, an ocean, and a littoral region.
 18. Themethod of claim 1, further comprising saturating the pre-existing wellwith the multi-phase composition.
 19. A multi-phase composition formitigating fracturing hits on an underground well, comprising: a gas anda nanoparticle fluid combined to form a well treatment fluid adapted tobe injectable into the underground well for resisting fracturing hits onthe underground well.
 20. The multi-phase composition of claim 19,wherein the gas comprises from 95% to 98% of the well treatment fluid.21. The multi-phase composition of claim 19, wherein the gas is selectedfrom the group consisting of liquefied gas, vaporized gas andnanoparticles, carbon dioxide, nitrogen, natural gas, natural gasliquids, liquefied carbon dioxide, and mixtures thereof.
 22. Themulti-phase composition of claim 19, further comprising at least oneinjectant selected from the group consisting of surfactants, freshwater, potassium chloride (KCl) water, diverters, and any injectantcompatible for use in oil field remediation.
 23. The multi-phasecomposition of claim 19, wherein the nanoparticle fluid comprisescolloidal silica nanoparticles.
 24. The multi-phase composition of claim23, wherein the colloidal silica nanoparticles comprise brine resistantcolloidal silica nanoparticles.
 25. The multi-phase composition of claim19, wherein the nanoparticle fluid comprises brine resistant colloidalsilica nanoparticles, and the multi-phase composition further comprisessurfactants.
 26. The multi-phase composition of claim 25, furthercomprising at least one terpene.
 27. The multi-phase composition ofclaim 19, wherein the nanoparticle fluid comprises less than 0.1 wt. %of nanoparticles or optionally comprises a range of from 0.05 wt. % to16 wt. % of nanoparticles.
 28. The multi-phase composition of claim 19,wherein the well treatment fluid comprises a fluid selected from thegroup consisting of a foam, an emulsion, and an energized solution. 29.The multi-phase composition of claim 19, wherein the well treatmentfluid saturates the underground well.